Strong acid precursor generating strong acid for use downhole in a subterranean formation

ABSTRACT

Methods and compositions involving a strong acid precursor that generates and/or releases a strong acid for use in a subterranean formation. In some embodiments, the methods include providing a treatment fluid comprising a base fluid and a strong acid precursor and introducing the treatment fluid in a wellbore penetrating at least a portion of a subterranean formation.

BACKGROUND

The present disclosure relates to methods and compositions for treatinga subterranean formation.

Treatment fluids may be used in a variety of subterranean treatmentoperations. As used herein, the terms “treat,” “treatment,” “treating,”and grammatical equivalents thereof refer to any subterranean operationthat uses a fluid in conjunction with achieving a desired functionand/or for a desired purpose. Use of these terms does not imply anyparticular action by the treatment fluid or a component thereof, unlessotherwise specified herein.

Some common subterranean treatment operations that employ treatmentfluids are acidizing operations. Illustrative acidizing operations mayinclude, for example, matrix acidizing, acid fracturing, scaledissolution and removal, polymer breaking, filter cake dissolution, andthe like. These acidizing operations may be used to accomplish a numberof purposes. Such purposes may include increasing or restoring thepermeability of subterranean formations so as to facilitate the flow ofoil and gas from the formation into the well. Additionally, the acidtreatments may also be used to remove deposits in the formation along asmuch of the hydrocarbon flow path as possible and/or to create new flowpaths as in matrix acidization.

Although acidizing a portion of a subterranean formation may bebeneficial, conventional acidizing systems have significant drawbacks.For example, one major problem associated with conventional acidizingtreatment systems is that deeper penetration into the formation is notusually achievable because, inter alia, the acid may be spent before itcan deeply penetrate into the subterranean formation. The rate at whichacidizing fluids react with reactive materials in the subterraneanformation is a function of various factors including, but not limitedto, acid strength, acid concentration, temperature, fluid velocity, masstransfer, and the type of reactive material encountered. Whatever therate of reaction of the acidic solution, the solution can be introducedinto the formation only a certain distance before it becomes spent. Tocombat these problems and others, it is desirable to generate and/orrelease a strong acid downhole for use in these and other variousapplications.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating an example of a subterranean formationin which a treatment fluid is introduced in accordance with certainembodiments of the present disclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

The present disclosure relates to methods and compositions for use in asubterranean formation. More particularly, the present disclosurerelates to methods and compositions involving a strong acid precursorthat generates and/or releases a strong acid for use in the subterraneanformation.

The present disclosure provides a composition including a base fluid anda strong acid precursor. The present disclosure also provides methodsthat include providing a treatment fluid including a base fluid and astrong acid precursor. The methods of the present disclosure may alsoinclude introducing the treatment fluid in a wellbore penetrating atleast a portion of a subterranean formation. In some embodiments, themethods may further include allowing the strong acid precursor togenerate and/or release a strong acid in the subterranean formation. Asused herein, the term “generate” and grammatical variants thereof shallbe understood to also include the terms “release,” “form,” “create,” andthe like and grammatical variants thereof. In some embodiments, themethods may further include allowing the strong acid to acidize theportion of the subterranean formation or damage contained therein. Insome embodiments, the methods may further include contacting at least aportion of a biopolymer or a filter cake located in the subterraneanformation with the strong acid, wherein the portion of the biopolymer orthe filter cake at least partially degrades. In some embodiments, themethods may further include introducing a catalytic acid or a catalyticacid precursor into the wellbore and contacting at least a portion ofthe treatment fluid with the catalytic acid or the catalytic acidprecursor.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods and compositions of the present disclosure may include a strongacid precursor that generates and/or releases a strong acid in situwithin a subterranean formation, which may avoid the strong acidbecoming prematurely spent (e.g., by reacting with the formation itself,fines, other chemicals, metal surfaces within the formation, and/orundesirable deposits nearest the wellbore) before performing its desiredpurpose in a desire location within the formation. In certainembodiments, the generation and/or release of the strong acid from thestrong acid precursor may be delayed until the treatment fluid includingthe strong acid precursor reaches a desired location within thesubterranean formation.

In some embodiments, the generation and/or release of the strong acid insitu within a subterranean formation may allow the strong acid topenetrate deeper into the formation than if the strong acid wasintroduced directly into the formation or a wellbore penetrating atleast a portion of the formation. Additionally, in some embodiments, themethods and compositions of the present disclosure may provide improveduniform placement of the strong acid in the subterranean formation. Forexample, an entire interval in the subterranean formation may be evenlysoaked with a strong acid as opposed to spot placement of the strongacid.

In certain embodiments, the strong acid that is generated and/orreleased in accordance with the methods and compositions of the presentdisclosure may be used in any suitable acidizing treatment to acidize atleast a portion of a subterranean formation or one or more depositscontained therein, such as deposits that may reduce permeability. Asused herein, the term “deposits” includes, but is not limited to, filtercakes, biopolymers, synthetic polymers, hydrates, surfactants (includingviscoelastic surfactants), bridging agents, scale deposits, skindeposits, and geological deposits. Furthermore, in some embodiments, themethods and compositions of the present disclosure may effectivelygenerate wormholes to stimulate production in carbonate-bearingsubterranean formations, dissolve damage, and remove fines to recoverproduction in formations at elevated temperatures.

In some embodiments, the methods and compositions of the presentdisclosure may also be less corrosive to tubing, casing, and otherdownhole equipment compared to conventional acidizing systems. Moreover,in some embodiments, the methods and compositions of the presentdisclosure may permit corrosion considerations to not be a limitingfactor in the design of the acidizing systems. Furthermore, the methodsand compositions of the present disclosure may reduce the hazardsassociated with acid handling for personnel and equipment. Additionally,the methods and compositions of the present disclosure may allow for theintroduction of more concentrated acids, especially as compared toconventional acidizing systems.

In certain embodiments, the methods of the present disclosure mayinclude providing a treatment fluid that includes a base fluid and astrong acid precursor. The treatment fluids prepared according to themethods and compositions of the present disclosure may include any basefluid known in the art. The term “base fluid” refers to the majorcomponent of the fluid (as opposed to components dissolved and/orsuspended therein), and does not indicate any particular condition orproperty of that fluid such as its mass, amount, pH, etc. Aqueous fluidsthat may be suitable for use in the methods of the present disclosuremay include water from any source. Such aqueous fluids may include freshwater, salt water (e.g., water containing one or more salts dissolvedtherein), brine (e.g., saturated salt water), seawater, or anycombination thereof. In some embodiments of the present disclosure, theaqueous fluids include one or more ionic species, such as those formedby salts dissolved in water. For example, seawater and/or produced watermay include a variety of divalent cationic species dissolved therein. Incertain embodiments, the density of the aqueous fluid can be adjusted,among other purposes, to provide additional particulate transport andsuspension in the methods of the present disclosure. In certainembodiments, the pH of the aqueous fluid may be adjusted (e.g., by abuffer or other pH adjusting agent) to a specific level, which maydepend on, among other factors, the types of viscosifying agents, acids,and other additives included in the fluid. One of ordinary skill in theart, with the benefit of this disclosure, will recognize when suchdensity and/or pH adjustments are appropriate. Examples of non-aqueousfluids that may be suitable for use in the methods of the presentdisclosure include, but are not limited to oils, hydrocarbons, organicliquids, and the like. In certain embodiments, the treatment fluids mayinclude a mixture of one or more fluids and/or gases, including but notlimited to emulsions, foams, and the like.

In certain embodiments, the strong acid precursors used in thecompositions and methods of the present disclosure may be any chemicalthat generates and/or releases a strong acid (e.g., HCl, HI, HBr, andHF) for use downhole in a subterranean formation. In some embodiments,the strong acid precursor includes at least one compound selected fromthe group consisting of

wherein each of R₁, R₄, R₅, and R₆ may be independently selected fromthe group consisting of: a hydrogen atom and a C₁ to C₁₀ hydrocarbonchain, wherein each of R₂ and R₃ may be independently a C₁ to C₁₀hydrocarbon chain, and wherein X may be a halogen selected from thegroup consisting of fluorine, chlorine, bromine, and iodine. As usedherein, a “hydrocarbon chain” may, unless otherwise specifically noted,be branched, unbranched, non-cyclic, and/or cyclic; it may besubstituted or unsubstituted (that is, it may or may not contain one ormore additional moieties or functional groups in place of one or morehydrogen atoms in the hydrocarbon chain); it may be saturated orunsaturated; and/or it may be bonded to at least one other hydrocarbonchain. Furthermore, as used herein, the nomenclature “C_(x) to Cy”refers to the number of carbon atoms in the hydrocarbon chain (here,ranging from x to y carbon atoms). As used herein, “independently”refers to the notion that the preceding items may be the same ordifferent. As used herein, the term “substituted” refers to one or moreof the hydrogen atoms in the hydrocarbon chain being replaced by one ormore functional groups. In such embodiments, the hydrocarbon chain maybe substituted with one or more functional groups selected from thegroup consisting of an ether, an ester, a hydroxyl, an alkane, analkene, an alkyne, and any combination thereof.

In certain embodiments, two or more of R₁, R₂, R₃, R₄, R₅, and/or R₆ maybe a C₁ to C₁₀ hydrocarbon chain and may be bonded together. In someembodiments, two or more of R₁, R₂, and/or R₃ may be a C₁ to C₁₀hydrocarbon chain and may be bonded together. In some embodiments, twoor more of R₄, R₅, and/or R₆ may be a C₁ to C₁₀ hydrocarbon chain andmay be bonded together. In such embodiments, the bonding together of twoor more of R₁, R₂, R₃, R₄, R₅, and/or R₆ may result in the formation ofa cyclic structure. In such embodiments, the cyclic structure mayinclude a C₂ to C₁₀ hydrocarbon chain. Examples of strong acid precursorcompounds of the present disclosure in which R₂ and R₃ are bondedtogether to form a cyclic structure include, but are not limited to:

In some embodiments, each of R₁, R₄, R₅, and R₆ may be a hydrogen. Insome embodiments, the length of the hydrocarbon chains for each of R₁,R₂, R₃, R₄, R₅, and R₆ may independently range between C₁ to C₂, C₁ toC₃, C₁ to C₄, C₁ to C₅, C₁ to C₆, C₁ to C₇, C₁ to C₈, C₁ to C₉, and, C₁to C₁₀. In some embodiments, the shorter chain lengths and/or theinclusion of hydroxyl groups, may increase the water solubility of thestrong acid precursor, among other reasons, to promote the generationand/or release of a strong acid.

In certain embodiments, the strong acid precursor may be present in thetreatment fluids of the present disclosure in an amount sufficient togenerate and/or release the desired amount of strong acid. In certainembodiments, the strong acid precursor may be present in the treatmentfluid in an amount from about 0.1% to about 50% by volume of thetreatment fluid. A person skilled in the art, with the benefit of thisdisclosure, will appreciate the amount of the strong acid precursor usedin the treatment fluid may vary depending upon the application of thetreatment fluid. As described elsewhere herein, in certain embodiments,the treatment fluids of the present disclosure may be used in acidizingapplications. In some such embodiments, the strong acid precursor may bepresent in the treatment fluid in an amount from about 1% to about 50%by volume of the treatment fluid. In other such embodiments, the strongacid precursor may be present in the treatment fluid in an amount fromabout 3% to about 40% by volume of the treatment fluid. In yet othersuch embodiments, the strong acid precursor may be present in thetreatment fluid in an amount from about 5% to about 20% by volume of thetreatment fluid.

As described elsewhere herein, in certain embodiments, the treatmentfluids of the present disclosure may be used in other applications,including, but not limited to, reducing the viscosity of a viscosifiedfracturing fluid. In some such embodiments, the strong acid precursormay be present in the treatment fluid in an amount from about 0.1% toabout 10% by volume of the treatment fluid. In other such embodiments,the strong acid precursor may be present in the treatment fluid in anamount from about 0.5% to about 7% by volume of the treatment fluid. Inyet other such embodiments, the strong acid precursor may be present inthe treatment fluid in an amount from about 1% to about 5% by volume ofthe treatment fluid.

In certain embodiments, the treatment fluids used in the methods andcompositions of the present disclosure may include one or more polarorganic solvents. In such embodiments, the polar organic solvent mayimprove the solubility of the strong acid precursor in aqueous basefluids. Organic polar solvents that may be suitable for use in certainembodiments of the present disclosure include alcohols, glycols, glycolethers, esters, amides, and their derivatives. Examples of organic polarsolvents include, but are not limited to, methanol, ethanol,isopropanol, n-butanol, iso-butanol, tert-butanol, ethylene glycol,polyethylene glycol, propylene glycol, butanediol, pentanediol,glycerol, polyglycerol, 2-pyrrolidone, N-methyl-2-pyrrolidone, ethyleneglycol monobutyl ether, polyglycol ethers, and combination thereof.

In certain embodiments, the polar organic solvent may be present in thetreatment fluid in an amount up to about 70% by volume of the treatmentfluid. In other embodiments, the polar organic solvent may be present inthe treatment fluid in an amount from about 1% to about 50% by volume ofthe treatment fluid. In other embodiments, the polar organic solvent maybe present in the treatment fluid in an amount from about 2% to about40% by volume of the treatment fluid. In other embodiments, the polarorganic solvent may be present in the treatment fluid in an amount fromabout 5% to about 30% by volume of the treatment fluid.

In certain embodiments, the treatment fluids used in the methods andcompositions of the present disclosure may include one or moresurfactants. Surfactants that may be suitable for use in certainembodiments of the present disclosure include cationic, anionic,zwitterionic, and nonionic surfactants. Examples of cationic surfactantsthat may be suitable for use in certain embodiments of the presentdisclosure include, but are not limited to, alkyl amines, alkyl aminesalts, quaternary ammonium salts such as trimethyltallowammonium halides(e.g., trimethyltallowammonium chloride, trimethyltallowammoniumbromide), amine oxides, alkyltrimethyl amines, triethyl amines,alkyldimethylbenzylamines, cetyltrimethylammonium bromide, alkyldimethyl benzyl-ammonium chloride, trimethylcocoammonium chloride,derivatives thereof, and any combination thereof. Examples of anionicsurfactants that may be suitable for use in certain embodiments of thepresent disclosure include, but are not limited to, alkyl carboxylates,alkylether carboxylates, N-acylaminoacids, N-acylglutamates,N-acylpolypeptides, alkylbenzenesulfonates, paraffinic sulfonates,α-olefinsulfonates, lignosulfates, derivatives of sulfosuccinates,polynapthylmethylsulfonates, alkyl sulfates, alkylethersulfates, C₈ toC₂₂ alkylethoxylate sulfate, alkylphenol ethoxylate sulfate (or saltsthereof), monoalkylphosphates, polyalkylphosphates, fatty acids, alkalisalts of fatty acids, glyceride sulfates, sodium salts of fatty acids,soaps, derivatives thereof, and combinations thereof. Examples ofamphoteric or zwitterionic surfactants that may be suitable for use incertain embodiments of the present disclosure include, but are notlimited to, dihydroxyl alkyl glycinate, alkyl ampho acetate orpropionate, alkyl betaine, alkyl amidopropyl betaine and alkyliminomono- or di-propionates derived from certain waxes, fats and oils.Examples of nonionic surfactants that may be suitable for use in certainembodiments of the present disclosure include, but are not limited to,alcohol oxylalkylates, alkyl phenol oxylalkylates, nonionic esters suchas sorbitan esters, alkoxylates of sorbitan esters, castor oilalkoxylates, fatty acid alkoxylates, lauryl alcohol alkoxylates,nonylphenol alkoxylates, octylphenol alkoxylates, and tridecyl alcoholalkoxylate, derivatives thereof, and any combination thereof. A personof skill in the art with the benefit of the present disclosure willunderstand how to select such surfactants that may be suitable for aparticular application of the methods and compositions of the presentdisclosure.

In certain embodiments, the surfactant may be present in the treatmentfluid in an amount up to about 2.0% by volume of the treatment fluid. Inother embodiments, the surfactant may be present in the treatment fluidin an amount from about 0.01% to about 2.0% by volume of the treatmentfluid. In other embodiments, the surfactant may be present in thetreatment fluid in an amount from about 0.2% to about 1.5% by volume ofthe treatment fluid. In other embodiments, the surfactant may be presentin the treatment fluid in an amount from about 0.5% to about 1.0% byvolume of the treatment fluid.

In certain embodiments, the treatment fluids used in the methods andcompositions of the present disclosure may include one or more corrosioninhibitors. Corrosion inhibitors that may be suitable for use in certainembodiments of the present disclosure include any surfactant that iscapable of inhibiting corrosion of metal surfaces (e.g., a film formingcorrosion inhibitor). In certain embodiments, the corrosion inhibitormay include a hydrophilic moiety, and the hydrophilic moiety may includea quaternary amine, imine, amide, imidazoline, pyridine, carboxylicacid, phosphate ester, thiol group, or any salt of any of the foregoing.In certain embodiments, the hydrophilic moiety may be attached to one ormore hydrocarbon chains having hydrophobic properties. Each hydrocarbonchain may independently include from about 8 to about 22 carbons and maybe linear or branched, cyclic or acyclic, and/or saturated orunsaturated. Each hydrocarbon chain may be independently substitutedwith a functional group including one or more of: ether, ester,hydroxyl, alkane, alkene, alkyne and any combination thereof. In certainembodiments, the corrosion inhibitor may be a film forming corrosioninhibitor.

In certain embodiments, the corrosion inhibitor may be present in thetreatment fluid in an amount up to about 2.0% by volume of the treatmentfluid. In other embodiments, the corrosion inhibitor may be present inthe treatment fluid in an amount from about 0.01% to about 2.0% byvolume of the treatment fluid. In other embodiments, the corrosioninhibitor may be present in the treatment fluid in an amount from about0.2% to about 1.5% by volume of the treatment fluid. In otherembodiments, the corrosion inhibitor may be present in the treatmentfluid in an amount from about 0.5% to about 1.0% by volume of thetreatment fluid.

In certain embodiments, the treatment fluids prepared according to themethods and compositions of the present disclosure optionally mayinclude any number of additional additives. Examples of such additivesinclude, but are not limited to, buffering agents, salts, acids,diverting agents, fluid loss control additives, gas, nitrogen, carbondioxide, surface modifying agents, tackifying agents, foamers, scaleinhibitors, emulsifiers, catalysts, clay stabilizers, shale inhibitors,biocides, friction reducers, antifoam agents, bridging agents,flocculants, H₂S scavengers, CO₂ scavengers, oxygen scavengers,lubricants, hydrocarbons, viscosifying/gelling agents, breakers,weighting agents, relative permeability modifiers, resins, wettingagents, coating enhancement agents, filter cake removal agents,antifreeze agents (e.g., ethylene glycol), proppant particles, and thelike. A person skilled in the art, with the benefit of this disclosure,will recognize the types of additives that may be included in the fluidsof the present disclosure for a particular application.

In certain embodiments, the methods of the present disclosure mayinclude introducing the treatment fluid including one or more strongacid precursors of the present disclosure into a wellbore penetrating atleast a portion of a subterranean formation. In certain embodiments ofthe present disclosure, the methods of the present disclosure may alsoinclude allowing the one or more strong acid precursors of the presentdisclosure to generate and/or release a strong acid in the subterraneanformation. Without being limited to any particular theory or mechanism,it is believed that the strong acid precursor may generate and/orrelease strong acid according to the following reaction sequences whenin the presence of water (e.g., from the treatment fluid or from thesubterranean formation):

In some embodiments, the treatment fluid may include an aqueous basefluid and the strong acid precursor, and the strong acid precursor maygenerate and/or release a strong acid in the treatment fluid. In otherembodiments, the treatment fluid may include a non-aqueous base fluidand the strong acid precursor. In such embodiments, at least a portionof the treatment fluid may contact an aqueous fluid located in thewellbore and/or subterranean formation, and the strong acid precursormay generate and/or release a strong acid in the presence of thataqueous fluid.

As shown in each of the reaction sequences above, in certainembodiments, the strong acid precursor may be an acetal or a ketal (A orE) that hydrolyzes to a hemiacetal or a hemiketal (B or F) and thenfurther to an aldehyde or a ketone (C or G), which subsequentlyundergoes β-elimination to generate and/or release stoichiometricamounts of a strong acid (e.g., HX) and an α,β-unsaturated aldehyde oran α,β-unsaturated ketone (D). A person skilled in the art, with thebenefit of this disclosure, will recognize that the strong acidprecursor shown in (A) and (E) in the above reaction sequences may be anacetal if R₁ is a hydrogen atom or may be a ketal if R₁ is a C₁ to C₁₀hydrocarbon chain.

A person skilled in the art, with the benefit of this disclosure, willrecognize that the rate of β-elimination for the aldehyde or ketone (Cor G) decreases based on the halogen X in the following order I>Br>Cl>F,with iodide having the highest rate of β-elimination and fluoride havingthe lowest rate off β-elimination. In certain embodiments, it may bedesirable to select a particular halogen based on the rate ofβ-elimination in order to control the timing of the generation and/orrelease of the strong acid. In certain embodiments, a halogen havinghigher rate of β-elimination may be used instead of a halogen having alower rate of β-elimination, for example, iodide or bromide instead ofchlorine or fluorine, in order to achieve a faster generation and/orrelease of the strong acid. In other embodiments, a halogen having lowerrate of β-elimination may be used instead of a halogen having a higherrate of β-elimination, for example, chlorine or fluorine instead ofiodide or bromide, in order to achieve a slower or delayed generationand/or release of the strong acid.

In certain embodiments, the hydrolysis shown in the above reactionsequence may be amplified under mildly acidic condition (e.g., pH lessthan 7). Accordingly, once the strong acid starts to generate and/orrelease, the hydrolysis shown in the above reaction sequence may becomeself-amplifying due to the presence of H⁺ in the fluid containing thestrong acid precursor. In certain embodiments, the hydrolysis shown inthe above reaction sequence may be initiated and/or accelerated throughthe introduction of a catalytic acid or a catalytic acid precursor,which may lower the pH of the fluid containing the strong acidprecursor. In certain embodiments, the hydrolysis shown in the abovereaction sequence may be initiated and/or accelerated by a change intemperature of the fluid containing the strong acid precursor (e.g., dueto the temperature of the subterranean formation).

In certain embodiments, it may be desirable to speed up the generationand/or release of the strong acid. In such embodiments, the methods ofthe present disclosure may include introducing a catalytic acid or acatalytic acid precursor into the wellbore. In some embodiments, thecatalytic acid or the catalytic acid precursor may be introducedseparately from the treatment fluid. In such embodiments, the catalyticacid or the catalytic acid precursor may contact the treatment fluid (orother fluid within the subterranean formation containing the strong acidprecursor) and initiate and/or accelerate hydrolysis of the strong acidprecursor, resulting in the generation and/or release of a strong acid.In other embodiments, the catalytic acid or the catalytic acid precursormay be included in the treatment fluid and introduced into the wellboreat the same time as the strong acid precursor. In such embodiments, thecatalytic acid or the catalytic acid precursor may initiate and/oraccelerate hydrolysis of the strong acid precursor, thereby resulting inthe generation and/or release of a strong acid shortly after theintroduction of the treatment fluid into the wellbore.

Examples of catalytic acids suitable for certain embodiments of thepresent disclosure include, but are not limited to, inorganic acids,sulphuric acid, sulfamic acid, acidic anhydrides, boric acid, borontrihalides, organoboranes, aluminum hydroxide, aluminum trihalides,trimethylaluminum, zinc dichloride, titanium tetrachloride, tindichloride, tin tetrachloride, ferric chloride, organic acids, formicacid, acetic acid, monochloroacetic acid, dichloroacetic acid,trichloroacetic acid, sulfinic acids, sulfonic acids, methanesulfonicacid, p-toluenesulfonic acid, lactic acid, glycolic acid, oxalic acid,propionic acid, butyric acid, and any combination thereof. Examples ofcatalytic acid precursors suitable for certain embodiments of thepresent disclosure include, but are not limited to, orthoesters,polyorthoesters, organic esters of carboxylic acids (e.g., formates,acetates, propanoates, lactates), sulfonates, and sulfates. In certainembodiments, the catalytic acid or the catalytic acid precursor may beintroduced in an amount from about 0.01% to about 5% by volume of thetreatment fluid. In some embodiments, the catalytic acid or thecatalytic acid precursor may be introduced in an amount from about 0.1%to about 5% by volume of the treatment fluid. In other embodiments, thecatalytic acid or the catalytic acid precursor may be introduced in anamount from about 0.5% to about 3% by volume of the treatment fluid.

In certain embodiments, the strong acid precursor used in the methodsand compositions of the present disclosure may generate and/or release astrong acid when exposed to a certain temperature (e.g., in asubterranean formation). In certain embodiments, the strong acidprecursor may generate and/or release a strong acid in a subterraneanformation having a temperature of from about 20° C. (68° F.) to about204° C. (400° F.). In some embodiments, the strong acid precursor maygenerate and/or release a strong acid in a subterranean formation havinga temperature of from about 20° C. (68° F.) to about 177° C. (350° F.).In other embodiments, the strong acid precursor may generate and/orrelease a strong acid in a subterranean formation having a temperatureof at least 20° C. (68° F.). In other embodiments, the strong acidprecursor may generate and/or release a strong acid in a subterraneanformation having a temperature as low as any of 25, 30, 35, 40, 45, 50,55, 60, 65, 70, 75, 80, 85, 90, 95, 100, 105, 110, 115, 120, 125, and130° C.

In certain embodiments, it may be desirable to slow down the generationand/or release of the strong acid to, for example, provide a desiredtime delay. In such embodiments, the methods of the present disclosuremay include introducing a base into the wellbore. In some embodiments,the base may be introduced separately from the treatment fluid. In suchembodiments, the base may contact the treatment fluid (or other fluidwithin the subterranean formation containing the strong acid precursor)and reduce the pH of the fluid, thereby slowing the generation and/orrelease of the strong acid. In other embodiments, the base may beincluded in the treatment fluid and introduced into the wellbore at thesame time as the strong acid precursor. In such embodiments, thetreatment fluid may have an initial pH of about 7.0 or greater. In someembodiments, the treatment fluid may have an initial pH of from about7.0 to about 14.0. In some embodiments, the treatment fluid may have aninitial pH of from about 8.0 to about 13.0. In other embodiments, thetreatment fluid may have an initial pH of from about 9.0 to about 13.0.

Examples of bases suitable for certain embodiments of the presentdisclosure include, but are not limited to, inorganic bases, alkalimetal or alkaline earth metal oxides, alkali metal or alkaline earthmetal hydroxides, alkali metal or alkaline earth metal carbonates,alkali metal or alkaline earth metal bicarbonates, ammonia, organicbases, ammonium hydroxides, tetramethylammonium hydroxide, amines,pyridines, imidazoles, and any combination thereof. In certainembodiments, the base may be introduced in an amount from about 0.01% toabout 10% by volume of the treatment fluid. In some embodiments, thebase may be introduced in an amount from about 0.1% to about 5% byvolume of the treatment fluid. In other embodiments, the base may beintroduced in an amount from about 1% to about 5% by volume of thetreatment fluid.

In certain embodiments, the pH of the treatment fluid may decrease afterbeing introduced into the wellbore. In some embodiments, the pH of thetreatment fluid may further decrease as time progresses after theintroduction of the treatment fluid into the wellbore, for example, asstrong acid is generated and/or released from the strong acid precursor.In certain embodiments, the pH of the treatment fluid may be about 3 orless after the treatment fluid is introduced into the wellbore. Incertain embodiments, the pH of the treatment fluid may be about 3 orless within about 2 hours after the treatment fluid is introduced intothe wellbore. In some embodiments, the pH of the treatment fluid may beabout 3 or less within about 24 hours after the treatment fluidintroduced into the wellbore. In other embodiments, the pH of thetreatment fluid may be about 3 or less within about 72 hours after thetreatment fluid is introduced into the wellbore. In other embodiments,the pH of the treatment fluid may be about 3 or less within about 5 daysafter the treatment fluid is introduced into the wellbore.

In some embodiments, the methods and compositions of the presentdisclosure may be used during or in conjunction with any subterraneanoperation. For example, the methods and compositions of the presentdisclosure may be used in the course of and/or after drilling operationsin which a wellbore has been drilled to penetrate a subterraneanformation. In certain embodiments, the treatment fluid of the presentdisclosure may be introduced into and/or circulated in the wellboreafter drilling to contact a biopolymer in the wellbore and/orsubterranean formation, among other purposes, to at least partiallydegrade and/or remove one or more portions of the biopolymer. Examplesof suitable biopolymers include, but are not limited to, xanthan gum,scleroglucan gum, diutan gum, guar gum, Whelan gum, and derivativesthereof, such as hydroxypropyl guar and carboxymethylhydroxypropyl guar,cellulose derivatives, such as hydroxyethylcellulose,carboxymethylcellulose, polyanionic cellulose, and starch and itsderivatives, such as pregelatinized starch and crosslinked starch, andany combinations thereof. In certain embodiments, this may beaccomplished using the pumping system and equipment used to circulatethe treatment fluid in the wellbore.

In another embodiment, the treatment fluids of the present disclosuremay be introduced into and/or circulated in the wellbore after drillingto contact a filter cake deposited on the walls of the wellbore and/orin the subterranean formation, among other purposes, to at leastpartially degrade and/or remove one or more portions of the filter cake.In another embodiment, the treatment fluids of the present disclosuremay be used just prior to placing cement and/or casing in the wellbore,among other reasons, in order to remove a filter cake from the wellbore.In such embodiments, the treatment fluids of the present disclosure maybe continuously pumped down the casing or pipe and upwardly through anannulus in the wellbore in contact with the filter cake as a pre-flushjust prior to introducing a spacer fluid and a cement slurry into theannulus. In some embodiments, the quantity of the treatment fluids ofthe present disclosure pumped through the annulus prior to when thecement slurry is introduced therein (as well as other compositions usedto dissolve components of the filter cake) may be a predeterminedquantity calculated to remove substantially all of the filter cake,which may provide for a more successful and efficient cementing job.

In other embodiments, the treatment fluids of the present disclosure maybe used in the course of a stimulation treatment. In such embodiments,the treatment fluids of the present disclosure may be introduced into aportion of a subterranean formation where it may be allowed to contactat least a portion of the subterranean formation and at least partiallydissolve carbonate minerals therein so as to create one or more voids inthe subterranean formation. Introduction of the treatment fluid may, incertain embodiments, be carried out at or above a pressure sufficient tocreate or enhance one or more fractures within the subterraneanformation. In other embodiments, introduction of the treatment fluid maybe carried out at a pressure below that which would create or enhanceone or more fractures within the subterranean formation.

In other embodiments, the treatment fluid of the present disclosure maybe used in the course of a fracturing treatment. In certain embodiments,the treatment fluids of the present disclosure may be introduced into aportion of a subterranean formation (e.g., one or more fractures)containing a viscosified fracturing fluid. In such embodiments, at leasta portion of the treatment fluid may contact the viscosified fracturingfluid to at least partially reduce the viscosity of the fracturingfluid. In some embodiments, the viscosified fracturing fluid may includeproppants, and the proppants may be deposited within the subterraneanformation, for example, within one or more fracture, as the viscosity ofthe fracturing fluid is at least partially reduced.

Other suitable subterranean operations in which the methods and/orcompositions of the present disclosure may be used include, but are notlimited to, pre-flush treatments, after-flush treatments, hydraulicfracturing treatments, sand control treatments (e.g., gravel packing),“frac-pack” treatments, wellbore clean-out treatments, stuck pipetreatments, filter cake removal treatments, skin remediation treatments,and other operations where a treatment fluid may be useful. In certainembodiments, the methods and compositions of the present disclosure mayalso be used in cleaning operations or treatments conducted at thesurface that are used to clean or prepare equipment or other componentsthat are subsequently used in subterranean operations.

The treatment fluids of the present disclosure may be prepared using anysuitable method and/or equipment (e.g., blenders, mixers, stirrers,etc.) known in the art at any time prior to their use. The treatmentfluids may be prepared at least in part at a well site or at an offsitelocation. In certain embodiments, the strong acid precursor and/or othercomponents of the treatment fluid may be metered directly into a basefluid to form a treatment fluid. In certain embodiments, the base fluidmay be mixed with the strong acid precursor and/or other components ofthe treatment fluid at a well site where the operation or treatment isconducted, either by batch mixing or continuous (“on-the-fly”) mixing.The term “on-the-fly” is used herein to include methods of combining twoor more components wherein a flowing stream of one element iscontinuously introduced into a flowing stream of another component sothat the streams are combined and mixed while continuing to flow as asingle stream as part of the on-going treatment. Such mixing can also bedescribed as “real-time” mixing. In other embodiments, the treatmentfluids of the present disclosure may be prepared, either in whole or inpart, at an offsite location and transported to the site where thetreatment or operation is conducted. In introducing a treatment fluid ofthe present disclosure into a portion of a subterranean formation, thecomponents of the treatment fluid may be mixed together at the surfaceand introduced into the formation together, or one or more componentsmay be introduced into the formation at the surface separately fromother components such that the components mix or intermingle in aportion of the formation to form a treatment fluid. In either such case,the treatment fluid is deemed to be introduced into at least a portionof the subterranean formation for purposes of the present disclosure.

Certain embodiments of the methods and compositions disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed compositions. Forexample, with reference to FIG. 1, the disclosed methods andcompositions may directly or indirectly affect one or more components orpieces of equipment associated with an example of a well and treatmentsystem, according to one or more embodiments. Referring now to FIG. 1, awell 160 is shown during an operation according to certain embodimentsof the present disclosure in a portion of a subterranean formation ofinterest 110 surrounding a wellbore 120. The subterranean formation ofinterest 110 may include acid-soluble components. The subterraneanformation may be a carbonate formation, sandstone formation, mixedcarbonate-sandstone formation, or any other subterranean formationsuitable for an acidizing treatment. The wellbore 120 extends from thesurface 130 and through a portion of the subterranean formation 110surrounding the horizontal portion of the wellbore. Although shown asvertical deviating to horizontal, the wellbore 120 may includehorizontal, vertical, slant, curved, and other types of wellboregeometries and orientations, and the treatment may be applied to asubterranean zone surrounding any portion of the wellbore. The wellbore120 can include a casing 140 that is cemented or otherwise secured tothe wellbore wall. The wellbore 120 can be uncased or include uncasedsections. Perforations can be formed in the casing 140 to allow fluidsand/or other materials to flow into the subterranean formation 110. Incased wells, perforations can be formed using shape charges, aperforating gun, hydro-jetting and/or other tools.

The well is shown with a work string 170 depending from the surface 130into the wellbore 120. A pump and blender system 150 is coupled to thework string 170 to pump the treatment fluid 100 into the wellbore 120.The working string 170 may include coiled tubing, jointed pipe, and/orother structures that allow fluid to flow into the wellbore 120. Theworking string 170 can include flow control devices, bypass valves,ports, and or other tools or well devices that control a flow of fluidfrom the interior of the working string 170 into the subterranean zone110. For example, the working string 170 may include ports adjacent thewellbore wall to communicate the treatment fluid 100 directly into thesubterranean formation 110, and/or the working string 170 may includeports that are spaced apart from the wellbore wall to communicate thetreatment fluid 100 into an annulus in the wellbore 120 between theworking string 170 and the wellbore wall.

The working string 170 and/or the wellbore 120 may include one or moresets of packers 180 that seal the annulus between the working string 170and wellbore 120 and/or a downhole portion of the wellbore 120 to definean interval of the wellbore 120 into which particulate materials and/ortreatment fluids will be pumped.

As shown, the wellbore 120 penetrates a portion 110 of the subterraneanformation, which may include a hydrocarbon-bearing reservoir. In somecases, a treatment fluid 100 may be pumped through the working string170 and into the portion 110 of the formation. In some embodiments, thetreatment fluid 100 may create wormholes 195 in the portion 110 of thesubterranean formation.

In some embodiments, the injection of the treatment fluid 100 may bemonitored at the well site. In some embodiments, wellbore conditions maybe monitored during injection. Examples of wellbore conditions that maybe suitable for use in the methods of the present disclosure include,but are not limited to temperature, pressure, skin, fluid distribution,flow rate, pH, any physical or chemical property of the formation orformation fluids, and any combination thereof. For example, in certainembodiments, the injection rate could be updated with the methods of thepresent disclosure during injection using conditions such as fluiddistribution and wellbore pressure.

In some embodiments, wellbore conditions of the present disclosure couldbe measured by sensors. In certain embodiments, sensors could be locatedin the wellbore. For purposes of this disclosure, the term “sensors” isunderstood to include sources (to emit and/or transmit energy and/orsignals), receivers (to receive and/or detect energy and/or signals),and transducers (to operate as a source and/or receiver). In certainembodiments, information from the sensors may be fed into a system ortool that can determine an injection rate or rate profile according tothe methods of the present disclosure.

It is also to be recognized that the disclosed treatment fluids maydirectly or indirectly affect the various downhole equipment and toolsthat may come into contact with the treatment fluids during operation.Such equipment and tools may include, but are not limited to, wellborecasing, wellbore liner, completion string, insert strings, drill string,coiled tubing, slickline, wireline, drill pipe, drill collars, mudmotors, downhole motors and/or pumps, surface-mounted motors and/orpumps, centralizers, turbolizers, scratchers, floats (e.g., shoes,collars, valves, etc.), logging tools and related telemetry equipment,actuators (e.g., electromechanical devices, hydromechanical devices,etc.), sliding sleeves, production sleeves, plugs, screens, filters,flow control devices (e.g., inflow control devices, autonomous inflowcontrol devices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like. Any of thesecomponents may be included in the systems generally described above inFIG. 1.

An embodiment of the present disclosure is a method that includes:providing a treatment fluid comprising a base fluid and a strong acidprecursor, wherein the strong acid precursor comprises at least onecompound selected from the group consisting of:

wherein each of R₁, R₄, R₅, and R₆ is independently selected from thegroup consisting of: a hydrogen atom and a C₁ to C₁₀ hydrocarbon chain,wherein each of R₂ and R₃ is independently a C₁ to C₁₀ hydrocarbonchain, and wherein X is a halogen selected from the group consisting offluorine, chlorine, bromine, and iodine; and introducing the treatmentfluid in a wellbore penetrating at least a portion of a subterraneanformation.

In one or more embodiments described in the preceding paragraph, thestrong acid precursor generates a strong acid in the subterraneanformation, wherein the strong acid is HX. In one or more embodimentsdescribed in the preceding paragraph, two or more of R₁, R₂, R₃, R₄, R₅,and R₆ are bonded together. In one or more embodiments described in thepreceding paragraph, allowing the strong acid to acidize the portion ofthe subterranean formation or damage contained therein. In one or moreembodiments described in the preceding paragraph, contacting at least aportion of a biopolymer or a filter cake located in the subterraneanformation with the strong acid, wherein the portion of the biopolymer orthe filter cake at least partially degrades. In one or more embodimentsdescribed in the preceding paragraph, introducing a catalytic acid or acatalytic acid precursor into the wellbore; and contacting at least aportion of the treatment fluid with the catalytic acid or the catalyticacid precursor. In one or more embodiments described in the precedingparagraph, the subterranean formation has a temperature of about 68° F.or more. In one or more embodiments described in the precedingparagraph, the treatment fluid has a pH of about 7 or greater whenintroduced into the wellbore, and wherein the pH of the treatment fluidis about 3 or less within about 2 hours after being introduced into thewellbore. In one or more embodiments described in the precedingparagraph, the treatment fluid is introduced in the wellbore using atleast one pump.

Another embodiment of the present disclosure is a method that includes:providing a treatment fluid comprising an aqueous base fluid and astrong acid precursor, wherein the strong acid precursor comprises atleast one compound selected from the group consisting of

wherein each of R₁, R₄, R₅, and R₆ is independently selected from thegroup consisting of: a hydrogen atom and a C₁ to C₁₀ hydrocarbon chain,wherein each of R₂ and R₃ is independently a C₁ to C₁₀ hydrocarbonchain, and wherein X is a halogen selected from the group consisting offluorine, chlorine, bromine, and iodine; introducing the treatment fluidin a wellbore penetrating at least a portion of a subterranean formationcomprising carbonate minerals; and allowing the strong acid precursor togenerate a strong acid.

In one or more embodiments described in the preceding paragraph,allowing the strong acid to dissolve at least a portion of the carbonateminerals in the subterranean formation. In one or more embodimentsdescribed in the preceding paragraph, contacting at least a portion of abiopolymer or a filter cake located in the subterranean formation withthe strong acid, wherein the portion of the biopolymer or the filtercake at least partially degrades. In one or more embodiments describedin the preceding paragraph, the biopolymer is selected from the groupconsisting of: xanthan gum, scleroglucan gum, diutan gum, guar gum,Whelan gum, hydroxypropyl guar, carboxymethylhydroxypropyl guar,cellulose, hydroxyethylcellulose, carboxymethylcellulose, polyanioniccellulose, starch, pregelatinized starch, crosslinked starch, and anycombinations thereof. In one or more embodiments described in thepreceding paragraph, introducing a catalytic acid or a catalytic acidprecursor into the wellbore; and contacting at least a portion of thetreatment fluid with the catalytic acid or the catalytic acid precursor.

Another embodiment of the present disclosure is a composition thatincludes: a base fluid; and a strong acid precursor that comprises atleast one compound selected from the group consisting of:

wherein each of R₁, R₄, R₅, and R₆ is independently selected from thegroup consisting of: a hydrogen atom and a C₁ to C₁₀ hydrocarbon chain,wherein each of R₂ and R₃ is independently a C₁ to C₁₀ hydrocarbonchain, and wherein X is a halogen selected from the group consisting offluorine, chlorine, bromine, and iodine.

In one or more embodiments described in the preceding paragraph, two ormore of R₁, R₂, R₃, R₄, R₅, and R₆ are bonded together. In one or moreembodiments described in the preceding paragraph, the strong acidprecursor is present in the composition in a concentration of from about1% to about 20% by volume of the composition. In one or more embodimentsdescribed in the preceding paragraph, the composition comprises anadditive chosen from the group consisting of: surfactants, corrosioninhibitors, buffering agents, salts, acids, diverting agents, fluid losscontrol additives, gas, nitrogen, carbon dioxide, surface modifyingagents, tackifying agents, foamers, scale inhibitors, emulsifiers,catalysts, clay stabilizers, shale inhibitors, biocides, frictionreducers, antifoam agents, bridging agents, flocculants, H₂S scavengers,CO₂ scavengers, oxygen scavengers, lubricants, hydrocarbons, gellingagents, breakers, weighting agents, relative permeability modifiers,resins, wetting agents, coating enhancement agents, filter cake removalagents, antifreeze agents, proppant particles, and combinations thereof.In one or more embodiments described in the preceding paragraph, acatalytic acid or a catalytic acid precursor. In one or more embodimentsdescribed in the preceding paragraph, the catalytic acid or thecatalytic acid precursor is present in the composition in aconcentration of from about 0.01% to about 5% by volume of thecomposition.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a treatment fluidcomprising a base fluid and an acid precursor, wherein the acidprecursor comprises at least one compound selected from the groupconsisting of

wherein each of R₁, R₄, R₅, and R₆ is independently selected from thegroup consisting of a hydrogen atom and a C₁ to C₁₀ hydrocarbon chain,wherein each of R₂ and R₃ is independently a C₁ to C₁₀ hydrocarbonchain, and wherein X is a halogen selected from the group consisting offluorine, chlorine, bromine, and iodine; and introducing the treatmentfluid in a wellbore penetrating at least a portion of a subterraneanformation.
 2. The method of claim 1, wherein the acid precursorgenerates an acid in the subterranean formation, wherein the acid is HX.3. The method of claim 1, wherein two or more of R₁, R₂, R₃, R₄, R₅, andR₆ are bonded together.
 4. The method of claim 2, further comprisingallowing the acid to acidize the portion of the subterranean formationor damage contained therein.
 5. The method of claim 2, furthercomprising contacting at least a portion of a biopolymer or a filtercake located in the subterranean formation with the acid, wherein theportion of the biopolymer or the filter cake at least partiallydegrades.
 6. The method of claim 1, further comprising: introducing acatalytic acid or a catalytic acid precursor into the wellbore; andcontacting at least a portion of the treatment fluid with the catalyticacid or the catalytic acid precursor.
 7. The method of claim 1, whereinthe subterranean formation has a temperature of about 68° F. or more. 8.The method of claim 2, wherein the treatment fluid has a pH of about 7or greater when introduced into the wellbore, and wherein the pH of thetreatment fluid is about 3 or less within about 2 hours after beingintroduced into the wellbore.
 9. The method of claim 1, wherein thetreatment fluid is introduced in the wellbore using at least one pump.10. The method of claim 1, wherein the acid precursor is present in thetreatment fluid in an amount from about 1% to about 50% by volume of thetreatment fluid.
 11. The method of claim 1, wherein the acid precursoris present in the treatment fluid in an amount from about 0.1% to about10% by volume of the treatment fluid.
 12. A method comprising: providinga treatment fluid comprising an aqueous base fluid and an acidprecursor, wherein the acid precursor comprises at least one compoundselected from the group consisting of

wherein each of R₁, R₄, R₅, and R₆ is independently selected from thegroup consisting of a hydrogen atom and a C₁ to C₁₀ hydrocarbon chain,wherein each of R₂ and R₃ is independently a C₁ to C₁₀ hydrocarbonchain, and wherein X is a halogen selected from the group consisting offluorine, chlorine, bromine, and iodine; introducing the treatment fluidin a wellbore penetrating at least a portion of a subterranean formationcomprising carbonate minerals; and allowing the acid precursor togenerate an acid.
 13. The method of claim 12, further comprisingallowing the acid to dissolve at least a portion of the carbonateminerals in the subterranean formation.
 14. The method of claim 12,further comprising contacting at least a portion of a biopolymer or afilter cake located in the subterranean formation with the acid, whereinthe portion of the biopolymer or the filter cake at least partiallydegrades.
 15. The method of claim 14, wherein the biopolymer is selectedfrom the group consisting of xanthan gum, scleroglucan gum, diutan gum,guar gum, Whelan gum, hydroxypropyl guar, carboxymethylhydroxypropylguar, cellulose, hydroxyethylcellulose, carboxymethylcellulose,polyanionic cellulose, starch, pregelatinized starch, crosslinkedstarch, and any combinations thereof.
 16. The method of claim 12,further comprising: introducing a catalytic acid or a catalytic acidprecursor into the wellbore; and contacting at least a portion of thetreatment fluid with the catalytic acid or the catalytic acid precursor.17. The method of claim 12, wherein the acid is HX.
 18. The method ofclaim 12, wherein the treatment fluid has a pH of about 7 or greaterwhen introduced into the wellbore, and wherein the pH of the treatmentfluid is about 3 or less within about 2 hours after being introducedinto the wellbore.
 19. The method of claim 12, wherein two or more ofR₁, R₂, R₃, R₄, R₅, and R₆ are bonded together.
 20. The method of claim12, wherein the subterranean formation has a temperature of about 68° F.or more.